Hydraulic fracturing is a process commonly used to increase the flow of desirable fluids, such as oil and gas, from a portion of a subterranean formation. Hydraulic fracturing operations generally involve pumping a viscous fracturing fluid into a subterranean formation or zone at a rate and pressure sufficient to cause the formation or zone to break down with the attendant production of one or more fractures. The pressure required to induce fractures in rock at a given depth is known as the “fracture gradient.” Nearly any fluid given enough volume and pressure can be used to fracture a subterranean formation. However, fracturing fluids generally include a viscosifying or gelling agent such as a cross-linked or uncross-linked polysaccharide material, or a viscoelastic surfactant, to affect the rheology by increasing viscosity of the fluid.
Viscosified fluid is commonly used to generate a hydraulic fracture to improve reservoir production. One of the most common types of viscosified fluids is polymer-based, such as a borate cross-linked guar fracturing fluid. However, when using polymer-based fracturing fluids, there may be a considerable amount of residual polymer left within the hydraulic fracture after the treatments. There may be cases where improvement in the amount of polymer removed from the fracture, particularly around the immediate wellbore region, may significantly enhance the rate of hydrocarbon recovery from the reservoir.
In some instances, an aqueous fracturing fluid may be separate from the fluid carrier of the proppant. For example, the fracturing fluid may be prepared including a viscosifying agent, such as a borate cross-linked hydroxypropyl guar gel. The cross-linked gel is introduced into a subterranean formation through a wellbore at a rate and pressure sufficient to result in initiation of a fracture in the formation and development of a filter cake to control fluid-loss. The first fluid may include a quantity of proppant. A second fracturing fluid also is prepared. The second fluid comprises a viscosifying agent and may or may not include a crosslinking agent for the viscosifying agent. A proppant is added to the second gel, and the fluid is introduced into the formation and into the fracture created by the first fluid. The second fluid functions to carry and transport the proppant into the created fracture and, more importantly, to induce a break of the filter cake formed from the first fluid. The second fluid causes an increase in the leak-off rate of the fluid through the fracture faces which improves the ability of the proppant to pack within the fracture by dehydration of the fracturing fluid. Unfortunately, the use of even one polysaccharide-containing fluid tends to cause formation damage when the filter cake formed is removed. Using two polysaccharide-containing fluids increases this risk.
Enhancing a fracture includes enlarging a pre-existing fracture in the formation. As the fracture is created or enhanced, a portion of the fluid contained in the viscous fracturing fluid leaks off into the formation, and a filter cake comprised of deposited gelling agent is built up on the walls of the fracture. Particulates, such as grains of sand, may be suspended in the fracturing fluid and introduced into the created fractures. As the viscous fracturing fluid leaks off into the formation, particulates aggregate in proppant packs within the fracture. The proppant packs function to prevent the fracture from fully closing upon the release of pressure, forming conductive channels through which fluids may flow to (or from) the wellbore.
Gravel packing is another subterranean application that involves the use of particulates suspended in a viscous fluid. A “gravel pack” is used to at least partially reduce the migration of unconsolidated formation fines into the wellbore. To form a gravel pack, particulate material, such as sand, is delivered downhole suspended in a viscous fluid. The fluid may then leak-off into the formation or be recovered from the wellbore. Gravel packing operations commonly involve placing a gravel pack screen in the wellbore neighboring a specified portion of the subterranean formation and packing the annulus between the screen and the subterranean formation with particulate materials. The particulates are sized to inhibit the passage of formation fines through the gravel pack with produced fluids.
In some situations, hydraulic-fracturing operations and gravel-packing operations may be combined into a single operation to stimulate production and to reduce the production of unconsolidated formation particulates. Such treatments are often referred to as “frac-pack” operations. In some cases, these treatments are completed with a gravel-pack screen assembly in place with the fracturing fluid being pumped through the annular space between the casing and screen. In such a situation, the fracturing operation may end in a screen-out condition creating an annular gravel pack between the screen and casing.
Gelling agents have heretofore been utilized to gel a base fluid, producing a fluid with adequately high viscosity. These gelling agents can be biopolymers or synthetic polymers that, when hydrated and at a sufficient concentration, are capable of forming a more viscosfied fluid. Common gelling agents include polysaccharides (such as xanthan, guar gum, diutan, succinoglycan, scleroglucan, etc.), synthetic polymers (such as polyacrylamide, polyacrylate, polyacrylamide copolymers, and polyacrylate copolymers), and surfactant gel systems. Guar and derivatized guar polymers, such as hydroxypropylguar, are economical water soluble polymers which can be used to create high viscosity aqueous fluids. Surfactant gel systems also have been used in subterranean formations at these temperatures, but such systems can be expensive, can be sensitive to impurities, and may require hydrocarbon breakers. To increase the viscosity of the resultant fluid, the gelling agents may be crosslinked through an applicable crosslinking reaction comprising a crosslinking agent. Conventional crosslinking agents usually comprise a metal complex or other compound that interacts with at least two polymer molecules to form a “crosslink” between them.
Typically, after a high viscosity, particulate-laden fluid is pumped into a wellbore and the particulates are placed as desired, the fluid will be caused to revert into a low viscosity fluid. This process is often referred to as “breaking” the fluid. The treatment fluid “breaks,” or decreases in viscosity, so that it can more easily be removed from the well, while leaving a proppant and/or gravel pack in the fracture. Breaking the gel is most commonly accomplished by adding a breaker to the treatment fluid prior to pumping it into the wellbore. Breakers, such as oxidizers, enzymes, and acid release agents, have been used successfully in breaking polymer-gelled fluids. Depending on the crosslinking agent used, a fluid may be broken by “delinking” the crosslinks between the gelling agent molecules. In such instances, this may be useful because oftentimes the fluid can be recovered, recrosslinked, and reused, whereas more typical “broken” fluids cannot. However, for typical crosslinked polymer hydraulic fracturing treatments, there is residual polymer which remains in the hydraulic fracture in the form of a filter cake after the treatment. Studies show that even though the polymeric filtercake may be termed “broken”, the mass of “broken” residual polymer is still difficult for the reservoir to produce fluids from the fracture during well production, as discussed in SPE 98746 “New Findings in Fracture Cleanup Change Common Industry Perceptions”. As a result, the disadvantage associated with using crosslinked polymer treatment fluids is that they can leave polymeric residue in the formation that can impact the productivity of the well (i.e. reduce fracture conductivity and the effective fracture length).
The ability to remove residual polymer post-stimulation operations has generated considerable interest in recent years. Attempts have been made to improve the composition and placement of clean-up fluids to remove residual polymer left behind by a polymer-gelled fluid but have often resulted in limited success. However, it would be desirable to provide a method by which residual polymer can be removed with a much more effective and simpler mechanism.